In the production of crude oil from wells, steam injection has been used to recover immobile heavy oils and to enhance the oil recovery from older wells where the natural field pressures are too low for unassisted production.
Steam stimulation and steam flooding are techniques generally used in reservoirs of high-viscosity oil. The techniques involve injection into the well of a high temperature steam (approximately 250.degree. C. or greater) in cycles of thousands of cubic meters at a time. The quality of this steam generally ranges from 60-80%, meaning that large quantities of liquid water, i.e. 40%-20% are concurrently injected into the well bore with the steam.
A typical oil well consists of a casing which lines the inside surface of the well bore and a length of tubing which extends downwardly through the casing. The casing serves to protect the tubing in the event of damage to the latter. Sucker rods extend through the tubing and terminate in a pump which reciprocates in the tubing and forces the oil upwardly therethrough. The lower end of the tubing extends into the oil zone and has perforations therein through which the oil flows thereinto.
Many wells which are subjected to steam stimulation have the lower end of the tubing filled with a gravel pack. A liner is positioned on top of the gravel pack and serves as a seat for the oil pump. The function of the gravel pack is to filter and prevent sand from being produced with the well fluid. The sand is erosive and if not filtered, would damage the pump. The gravel used to pack the well consists of granular sand grains. This material is principally quartz or silica.
Silica has a very low solubility in water at neutral pH and low temperatures, but this solubility rises sharply as temperature and pH are increased. For pH values above 11.0 and temperatures above 177.degree. C., the dissolution rates are orders of magnitude higher than at neutral/ambient conditions.
When groundwater or river or lake water are used in a steam generator to generate steam, the gaseous phase, i.e., steam, and the residual fluid phase, i.e., water, have opposite pH's but similar undesirable reaction characteristics with the reservoir rocks. The residual liquid water produced in a steam generator generally has a pH in excess of 11.0. The steam, when condensed, has an acidic pH of about 4.0-4.5. This partitioning is due to the contained bicarbonate HCO.sub.3 -) in the source water which decomposes into CO.sub.2 and enters the steam phase leaving the residual fluid deficient in anionic components and thus produces a pH rise proportional to the lost anionic carbonate species.
Coupled with the high liquid and steam temperatures, the fluid and steam are capable of rapidly dissolving the gravel pack or reservoir rocks, such as sandstone, quartz, diatomite, porcellanite, and the like. In the event of failure of the gravel pack, the well begins to produce sand with the eventual shut-down of the well. Alternatively, the formation collapses and the permeability is reduced.
Not only is the rate of silica dissolution quite rapid, but the water in the well becomes saturated within a short distance from the point at which the fluid contacts the surface of the silica. This is significant in that the dissolution of silica tends to be localized rather than diffused over a wide area of the zone, resulting in the face of the zone receding significantly.
In addition to the dissolution of the gravel pack due to the large quantities of water injected, there is a danger of the face of the formation also being eroded. If this occurs to a sizable extent, formation caves in and even tubing or casing collapse could result, resulting in the loss of the well.
Still further, these large silica or carbonate losses at the well bore may precipitate out as the fluid reaches supersaturated conditions as it passes through the zone. The precipitation of the silica or carbonate in the zone may result in loss of zone permeability and a resultant shut-in.
The costs resulting from such well failures are imposing. Recently, one large oil producer estimated a well failure rate of 34% due to failure of gravel packing or formation zone related problems due to steaming. The approximate cost of reworking a well presently runs over 35,000. Reducing the cycle by even one day would realize significant savings.
Dissolution of the gravel pack has been shown to be primarily a function of the pH and temperature of the injected liquid-phase water. Consequently, prior attempts at solution of the problem have focused on these aspects. For example, by keeping the pH of the injected hot water below 9.5, gravel pack dissolution can be decreased sharply. This may be accomplished by (1) selection of feed waters having low HCO.sub.3 -ion concentrations (&gt;10 mg HCO.sub.3 -/L), (2) treating the feed water with HCl to yield the desired effluent pH, (3) using a total deionizer to remove both cations and anions from the feed water, or (4) protectively coating the gravel and/or reservoir rocks.
With regard to the first proposed solution, selection of feed waters is often impractical as the large quantities of water used are not available from a choice of sources. With regard to the second proposed solution, the use of HCl to neutralize the bicarbonate alkalinity suffers from considerations of cost as well as feasibility of the method. That is, addition of too much acid will cause severe corrosion of the steam generator and too little will result in insufficient depression of the pH to alleviate silica loss. With regard to the third proposed solution, the cost of a total deionizer is prohibitive, both in terms of capital costs as well as operating costs. With regard to the fourth proposed solution, complete coating of the gravel with a material, such as soybean lecithin described in U.S. Pat. No. 4,323,124, is not assured and driving the material out into the reservoir toward the production is impractical. Furthermore, the '124 patent does not address the problems of formation dissolution out in the formation away from the well bore.
U.S. Pat. No. 3,438,443 discloses another approach for a solution to the problem through the use of alkali metal silicates to saturate the water phase with silica and thus, hopefully, preventing the dissolution of siliceous formation material. However, alkali metal silicates are costly and the process also requires careful pH control.
Still other oil recovery processes as described in U.S. Pat. Nos. 3,500,931; 4,222,439; and 4,223,731 utilize chemicals, such as ammonium hydroxide, ammonium bisulfite, ammonium sulfite in separate injection steps to enhance oil recovery. However, these processes utilize the chemicals in a separate step, generally not including steam, and do not recognize the problems associated with the pH partitioning between the steam phase and the residual water phase. Still another oil recovery process described in U.S. Pat. No. 4,441,555 utilizes a carbonated water flooding step before a steam drive to enhance the recovery of viscous oil. This process also does not recognize the problems of pH partitioning during steam drives.
Recently, U.S. application Ser. No. 654,331, filed Sept. 9, 1984, solved the problem by adding various compounds such as ammonium salts to the steam injection feed water. Although viable, the salts may interfere with the use of surfactants. In addition, situations occur where the use of a gas medium to solve this problem may be preferable.
Thus, it would be highly desirable to have a gaseous process of reducing the pH of the residual fluid without adversely affecting the pH of the steam phase in a steam-enhanced oil recovery process. A further optional and beneficial advantage would be to have the process compatible with steam-surfactant enhanced oil recovery processes. Achieving these results would have other additional desirable benefits which would be obvious to the ordinary skilled artisan, such as use for in situ solution mining and the like.